Various drilling methods and systems are known in the art. Most arrangements use a rotating drill bit that is carried and conveyed in the wellbore by a drill string, which is in turn carried by a drilling rig located above the wellbore. The drill bit may be rotated by the drill string, and the drill string may also include as part of a bottom hole assembly downhole rotary motor for rotating the drill bit.
The drill string is substantially made up of individual stands of drill pipe that are assembled as the drill bit advances into the earth. Drilling fluid is pumped to the drill bit through the drill string and is directed out of nozzles in the drill bit for cooling the bit and removing formation cuttings. The drilling fluid may also serve the purpose of providing hydraulic power to downhole tools, such as a mud motor located in a bottom hole assembly (BHA) for rotating the drill bit. The spent drilling fluid and entrained formation cuttings are forced from the bottom of the wellbore and carried upwards through the annulus that exists between the drill string and the wellbore wall.
In cases of drilling offshore wells, the drilling rig is positioned above the surface of the water, generally over the wellbore. A riser is commonly provided between the drilling rig and the wellbore at the seafloor for allowing the drill string to be conveniently run into and tripped out of the wellbore. The riser also provides an extension of the annular wellbore flow path for returning the drilling fluid and cuttings to the rig for processing and reuse.
Recently developed drilling methods and systems may substitute a coaxial dual drill string in place of the prolific single-pipe drill string. A coaxial dual drill string has an inner pipe fixed within an outer pipe, thereby defining an inner flow channel within the inner pipe and an outer flow channel within the annular region defined between the inner and outer pipes.
In such arrangements, drilling fluid may be supplied to the drill bit via the outer flow channel, and the return drilling fluid, laden with formation cuttings, may be removed from the wellbore via the inner flow channel. A single crossover port may be provided at a distal end of the drill sting, commonly at a location just uphole of the BHA, if supplied, which fluidly connects the inner flow path to the wellbore, thereby allowing spent drilling fluid at the bottom of the wellbore to re-enter the drill string and return uphole via the inner flow channel.
The use of a dual drill string as has been generally described includes a flow channel for return drilling fluid flow and may provide several advantages over drilling with single-pipe drill string. In certain offshore conditions, such a system may obviate the need to deploy a drilling riser, provided an alternative barrier between the seawater and the wellbore annulus is established. The return flow channel leaves the wellbore clear of formation cuttings. Improved hole cleaning results in less downtime. Finally, because the entire wellbore annulus no longer forms a flow path for drilling fluid circulation, the fluid within the wellbore annulus is essentially static, which may be preferable for certain techniques for managing wellbore pressure.